Fields of Disclosure
The disclosure relates generally to the field of fluid separation. More specifically, the disclosure relates to the cryogenic separation of contaminants, such as acid gas, from a hydrocarbon.
Description of Related Art
This section is intended to introduce various aspects of the art, which may be associated with the present disclosure. This discussion is intended to provide a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
The production of natural gas hydrocarbons, such as methane and ethane, from a reservoir oftentimes carries with it the incidental production of non-hydrocarbon gases. Such gases include contaminants, such as at least one of carbon dioxide (“CO2”), hydrogen sulfide (“H2S”), carbonyl sulfide, carbon disulfide and various mercaptans. When a feed stream being produced from a reservoir includes these contaminants mixed with hydrocarbons, the stream is oftentimes referred to as “sour gas.”
Many natural gas reservoirs have relatively low percentages of hydrocarbons and relatively high percentages of contaminants. Contaminants may act as a diluent and lower the heat content of hydrocarbons. Some contaminants, like sulfur-bearing compounds, are noxious and may even be lethal. Additionally, in the presence of water some contaminants can become quite corrosive.
It is desirable to remove contaminants from a stream containing hydrocarbons to produce sweet and concentrated hydrocarbons. Specifications for pipeline quality natural gas typically call for a maximum of 2-4% CO2 and ¼ grain H2S per 100 scf (4 ppmv) or 5 mg/Nm3 H2S. Specifications for lower temperature processes such as natural gas liquefaction plants or nitrogen rejection units typically require less than 50 ppm CO2.
Separation by distillation of some mixtures can be relatively simple and, as such, is widely used in the natural gas industry. However, distillation of mixtures of natural gas hydrocarbons, primarily methane, and one of the most common contaminants in natural gas, carbon dioxide, can present significant difficulties. Conventional distillation principles and conventional distillation equipment are predicated on the presence of only vapor and liquid phases throughout the distillation tower. The separation of CO2 from methane by distillation involves temperature and pressure conditions that result in solidification of CO2 if a pipeline or better quality hydrocarbon product is desired. The required temperatures are cold temperatures typically referred to as cryogenic temperatures.
Certain cryogenic distillations can overcome the above mentioned difficulties. These cryogenic distillations provide the appropriate mechanism to handle the formation and subsequent melting of solids during the separation of solid-forming contaminants from hydrocarbons. The formation of solid contaminants in equilibrium with vapor-liquid mixtures of hydrocarbons and contaminants at particular conditions of temperature and pressure takes place in a controlled freeze zone section.
Certain cryogenic distillations can overcome the above mentioned difficulties. These cryogenic distillations provide the appropriate mechanism to handle the formation and subsequent melting of solids during the separation of solid forming contaminants from hydrocarbons. The formation of solid contaminants in equilibrium with vapor-liquid mixtures of the hydrocarbons and contaminants at particular conditions of temperature and pressure takes place in a controlled freeze zone section.
For cryogenic distillation and the controlled freeze zone section to work properly, the feed stream entering the distillation tower must be sufficiently dehydrated. Most often the feed stream for cryogenic distillation is dehydrated in a dehydration unit comprising a molecular sieve. The dehydration unit removes water from the feed stream to prevent the water from later presenting a problem in the distillation tower. Water can present a problem by forming a separate water phase (i.e., ice and/or hydrate) that negatively affects the distillation process in the distillation tower.
Although the molecular sieve can sufficiently dehydrate the feed stream, molecular sieves can be expensive, be heavy, and require a lot of energy. Thus, there is a desire to use a dehydration unit that is less expensive, lighter and/or does not require as much energy as a molecular sieve. Some to all of these requirements could be met if the amount of carbon dioxide in the feed stream entering the distillation tower is greater than 25% as liquid carbon dioxide has a significant water moisture carrying capacity that can be used advantageously to reduce dehydration requirements. But many feed streams do not contain this much carbon dioxide when the feed stream enters the distillation tower.
While there are other dehydration units or systems, such as glycol-based units, that can dehydrate the feed stream and use less energy than a molecular sieve, glycol-based units alone cannot dehydrate the feed stream enough to prevent the formation of a separate water phase without the help of the moisture carrying capacity of sufficient carbon dioxide in the feed stream. Consequently, separate water phases may result when the feed stream entering the distillation tower has less than 25% carbon dioxide and the dehydration unit comprises a glycol-based dehydration unit. As a result, the distillation tower cannot successfully operate to separate contaminants from methane.
A need, therefore, exists for improved technology, including technology that may address one or more of the above described disadvantages. Specifically, a need exists for a method and system that dehydrates a feed stream processed in a distillation tower.